On December 20th, President Barack Obama, under urging from environmentalists and Democratic Congress members, moved to indefinitely block oil and natural gas drilling in U.S. waters in large sections of the Arctic and Atlantic oceans. Using a provision in the Outer Continental Shelf Lands Act of 1953, President Obama effectively banned offshore drilling in 118.8 million acres of U.S. waters. This covers a large majority of the Beaufort and Chukchi seas in the Arctic and 31 underwater canyons in the Atlantic. The move comes as a direct counter to President-elect Donald Trump’s campaign promise to increase domestic oil and natural gas production.

The law does not state a clear provision for reversal; therefore, the ban will hold in place pending what will most likely be a lengthy legal battle or action from Congress to amend the underlying Act. It is certainly not permanent, but not something that President-elect Trump can simply throw in the back of the Obamas’ U-Haul as it pulls away from the White House. So the question becomes “Is this simply political posturing or something that will have a significant impact on oil and gas production and pricing?”

According to Bureau of Ocean Energy Management (BOEM) estimates, there are nearly 31 billion barrels of oil and 169 trillion cubic feet of natural gas classified as undiscovered and technically recoverable in the Arctic and Atlantic outer continental shelf of the United States. That’s an impressive amount, but comes with significant challenges to drilling. The BOEM forecasts that crude oil prices would need to be $100 per barrel or natural gas prices $5.34 per Mcf for the resources to be drilled economically. Royal Dutch Shell had been the only company actively exploring in the Chukchi Sea off the Alaskan coast, but halted those plans earlier this year and took a $4.1 billion loss for their efforts.

The bottom line is this action will have little to no impact on near term oil and natural gas pricing. What it does impact is the ability of producers to plan operations in those areas. It can take years of planning and billions of dollars to drill and move these resources to market and this uncertainty will make it hard for producers to commit resources to these areas. Drilling efforts will most likely continue to be concentrated in the Gulf of Mexico and onshore shale plays, leaving these areas dormant until a clearer policy is established. President-elect Trump has made it clear that his energy plan will be fossil fuel friendly so we can expect that he will work to overturn this ban. How successful he proves to be will go a long way towards determining if these large reserves of oil and gas ever have the opportunity to become part of the U.S. energy mix.

The Edison Electric Institute (EEI), an investor-owned electric utility trade organization, estimates its member electric companies spent $120 billion in 2016 grid work and clean energy development. To better understand the magnitude of this investment, consider year-end 2015 investor-owned electric utilities’ net assets in service were $898 billion, according to the EEI. Since 2016, capital spending represents over 10 percent of the 2015 net assets in service. Expecting no rate increase would simply be naive.

Regulated electric utility assets have trended upward over the last several years while revenue has trended down. Energy efficiency efforts and offshore (formerly domestic based) U.S. manufacturing has constrained electricity demand, according to the EEI. (Annual growth in electricity output from 2013 to 2015 has been under one-half of one percent.) Spreading increasing fixed costs over fewer megawatt-hours means utilities need to increase rates to adequately recover costs.

Regulators are sensitive to utility cost recovery, so consumers should expect to see continued approval of rate increases. While utility commissions are charged with granting appropriate rate increases, protecting all consumer segments is a balancing act which often yields in favor of the residential rate class. Consequently, commercial and industrial consumers are more frequently participating in rate cases as interveners.

The rate case process involves two primary decisions: identifying allowable costs; and determining cost allocation among the rate classes. All interveners receive a common benefit when their collective efforts reduce the amount of allowable costs. However, interveners often have competing interest on cost allocation. Residential customers are automatic interveners, represented often by the state office of the attorney general. Absent other intervening groups, costs are sure to be allocated to the advantage of residential customers at the cost of commercial and industrial consumers.

Another regulatory proceeding to monitor relates to the electric utility’s long range plan. This “Resource Plan” describes supply and demand side capital initiatives and resulting rate impact scenarios. While these proceedings tend to fall below the public’s “radar,” stakeholders are paying increasingly more attention because of future cost and environmental impact.

As the electric utility industry continues to invest significant capital in transforming the grid and reducing carbon, consumers can ill afford to remain passive. Prepare to engage!

I recall a time when I worked for a natural gas utility (Local Distribution Company – LDC) here in Colorado. Gas Transportation was somewhat of a newer service offering (some 20+ years ago) and was starting to gain some traction in the local marketplace. Marketers flooded the arena, explaining to potential customers how this service worked and how it may benefit their natural gas spend (lower and/or controlled costs). They no longer had to accept the utility’s gas sales rates but could instead have access to the open market and competition. Many potential customers assumed that such marketers had a good understanding of what they were promoting and selling. Imbalance management was a service many marketers capitalized on.

I specifically recall one gas marketer who was somehow happily and surprisingly shocked that he was receiving monthly checks from the LDC. These monthly checks were akin to getting a gift for no apparent occasion as far as he was concerned. His misconception drove him to intentionally create sizable over delivered imbalances every single month on the LDC’s system in order to receive a check. Somehow, he genuinely believed he was gaming the system and taking advantage of the LDC. What he did not seemingly understand was that the LDC was actually buying his excess gas supply at a heavily discounted rate.

I suspect this marketer simply had no idea that this “gift” was actually costing his company greatly. The marketer did not last long operating under this gross misunderstanding. This is a clear example of not appreciating imbalance management as a real cost component and not grasping the consequences for mismanagement.

Let’s start with the foundational basics. So what exactly is an imbalance? It is the variance between what a Shipper has available for its use (Confirmed Receipt) and its actual demand (metered/transported volume).

Example:

Confirmed Receipt

Metered Volume

Imbalance

Position

100 dth

132 dth

(32) dth

Under delivery

100 dth

85 dth

+ 15 dth

Over delivery

An imbalance is often calculated on a daily basis and may accumulate over the course of the month with the sum of the daily imbalances resulting in a Monthly Imbalance. Think of the above scenario like a checking account. A Confirmed Receipt is similar to a deposit to the account and the metered volume is similar to a withdrawal on the account. The Shipper’s (the checking account holder in this illustration) goal should be to keep its deposits and withdrawals fairly close to one another so that the net effect (imbalance) is as close to zero as reasonably possible at the end of some designated time period.

Let’s focus on monthly balancing on a LDC’s system. A Shipper is said to be over delivered when at the end of the month, the Shipper has delivered more gas supply to the LDC than it required. Conversely, if the Shipper has used more gas than it delivered to the LDC, then the Shipper is said to be under delivered.

So what happens to this imbalance and why does it matter?

The LDC’s tariff will likely outline how the Shipper’s imbalance position shall be cured. A LDC may allow the Shipper to carry the imbalance forward into the next month with certain gas scheduling procedures available for curing the imbalance. A Shipper may also have the option to trade their imbalance with another Shipper on the LDC’s system so long as the imbalance trade improves both parties imbalance position meaning the imbalances must be in opposite directions. The LDC may even implement a Cashout policy as the imbalance cure. For instance, a LDC may purchase an over delivered volume from the Shipper or sell gas supply to an under delivered Shipper.

Cashouts are generally structured to be punitive to Shippers in order to encourage responsible imbalance management practices. The LDC cashout rate for the purchase of gas supply may be at prices less than market price (discounted price), meaning the Shipper will pay a higher rate for its gas supply than what the Shipper will receive in return (as was the case noted above). In the case of an under delivery, the LDC may sell gas to a Shipper at an above market price (inflated price). The Shipper is subjected to an additional cost for the imbalance in either case.

Some LDCs have Imbalance Tiers which are dependent on end of period imbalance percentages (formula for an imbalance percentage = Dth Imbalance/Dth Usage). As the imbalance percent increases, so does the related costs. A higher tiered over delivered imbalance may be cashed out at a more heavily discounted price, whereas a higher tiered under delivered imbalance may be cashed out at a higher premium.

LDCs also desire to keep their sales customers insulated from any cost causing behavior of Shippers. Imbalance policies and procedures can be an effective tool used to influence a Shipper’s management of imbalances. The lack of imbalance provisions may result in a Shipper taking advantage of a LDC’s rate payers by using or not using its own gas supply depending on actual market price conditions. Imbalance policies and provisions give the LDC some level of assurance that Shippers will conduct business in a responsible manner and also provide a means of recovery for the mismanagement of imbalances.

Balancing service is not always available to Shippers. A LDC may, from time to time, call a restriction (sometimes known as an Operational Flow Order or OFO) when its ability to meet its firm obligations (sales customers and firm Shippers) is jeopardized. Balancing on the LDC is either not available or available under limits during an OFO. If an OFO has been called for over delivery restrictions, this means the Shipper should at a minimum use the gas supply it delivers to the LDC. Such events may happen during warmer periods or when storage capacity is limited. An OFO for under delivery means the Shipper should avoid using more gas than it has delivered to the LDC. This may happen during periods of extreme cold and when the LDC’s ability to meet the demand of its sales customers and Firm Shippers (priority of service) is compromised. Non-compliance with an OFO typically results in OFO related penalties and in rare cases even curtailment.

Shippers should have a good understanding of tariff policies and procedures related to imbalance management. Imbalance positions should be monitored regularly and corresponding adjustments made to Confirmed Receipts. Effective imbalance management can be a vital piece of managing the overall delivered gas costs for a Shipper through penalty avoidance and the mitigation of cashout costs. Imbalances are certainly not intended to be a gift that keeps on giving.

You frequently hear the saying, “everything is bigger in Texas.” Why? The saying supposedly originated as a reference to the state’s size versus the other lower 48 states; plus Texas is second in size only to Alaska based on square miles. Texas is so big that you can take 10 of the smallest American states combined and cover only half of its square mile total. Texas also ranks second in population with California being number one.

Since you didn’t log onto an energy website for a geography lesson, the reason this saying rings true when dealing with energy is due the most recent U.S. Geological Survey study on the Wolfcamp shale. This formation has been crowned the largest unconventional crude accumulation ever assessed in the United States that is deemed technically recoverable. It’s nearly three times larger than the Bakken play located in North Dakota.

The Wolfcamp shale formation is located in West Texas (see map) and covers a little piece of ground in the southeast corner of New Mexico. It is located in the Midland Basin within the Permian Basin – historically a very lucrative area of oil and natural gas. The recent estimates indicate the formation could hold as many as 20 billion barrels of crude oil valued at around $1 trillion based on recent crude market prices. In addition to the crude, the formation will reportedly yield a projected 16 trillion cubic feet of natural gas and 1.6 billion barrels of natural gas liquids. The natural gas in this play alone would supply the entire United States demand for over six months as a sole source of supply. All of these resources are said to be trapped under four layers of shale and a mile in thickness in some locations.

The Permian Basin has been gushing crude since the 1920’s. The Wolfcamp area has been a location for vertical drilling since the 1980’s. It has been only recently that the full potential has been realized due to technological advances and techniques in extraction. Horizontal drilling is occurring in the area now, and more than 3,000 wells have been drilled and completed. Exploration companies have rushed to the area, grabbing up land for future wells.

While there still are some factors that may sway the strength and importance of the Wolfcamp play’s future production, the finding of the resource is big not only for the state of Texas but for the entire domestic energy sector. So when you hear the saying, “everything is bigger in Texas,” don’t think only about the land mass or the population. You can reflect upon the state’s contribution to the domestic energy sector and the “big” potential of the Wolfcamp basin.

Storing Electricity the Old-Fashioned Way with New Technology – Pumped Storage Hydropower

Author: Jean Stammeyer, Account Manager, Kinect Energy

An abundance of technology and research has been dedicated to developing ways to store electricity such as high tech batteries, mechanical flywheels and compressed air energy storage.

However, with the increased supply in wind and solar generation many utilities have turned to a much older, time-tested technology – pumped storage hydropower. Hydropower has been around since the late 1800s and the origins of the technology reach back thousands of years. The ancient cultures of Greece and China used water-powered mills for necessary activities such as grinding wheat. In 1849, an engineer named James Francis developed the Francis Turbine. This is the same type of turbine most widely used today.

Hydropower Milestones

1849: Invention of the Francis turbine.

1882: The world’s first hydropower plant begins operations in Appleton, Wisconsin, on the Fox River.

1887: The first hydroelectric plant opens in the West, in San Bernadino, California.

1907: Hydropower accounts for 15 percent of U.S. electrical generation.

1920: Hydropower accounts for 25 percent of U.S. electrical generation.

1931: Construction begins on the Hoover Dam, ultimately employing a total of more than 20,000 workers during the Great Depression.

1937: The Hoover Dam begins to generate power on the Colorado River.

1941-1945: Bureau of Reclamation dams ramped up power output to support America’s efforts in World War II, producing enough electricity to make 69,000 airplanes and 5,000 ships and tanks during a five year period.

Today: A vast expansion of hydropower’s potential is possible through new technologies for conventional, pumped storage and marine and hydrokinetic projects, modernizing existing hydropower facilities and adding generation to existing non-powered dams

Source; DOE

Pumped storage provides grid reliability on a large scale and is an affordable means of storing and deploying electricity. Pumped storage projects store and generate electricity by moving water between two reservoirs at different elevations. On nights and weekends when the demand for electricity is low, the surplus energy is used to pump the water to the upper reservoir. During the work week and on hot summer days when demand for electricity is high, the stored water is released through the turbines in the same manner as a conventional hydro station, flowing downhill from the upper reservoir into the lower reservoir, generating electricity. The turbine also acts as a pump, moving the water back uphill.

The U. S. has more than 20GW of pumped storage capacity today. There are facilities in every region of the country with proposals to develop an additional 31 GW of capacity. The majority of the projects are currently planned in the west region in support of the increasing amount of variable generation coming on line. Clean and renewable energy sources are constantly evolving creating the need for large scale storage. New technologies are being developed to store and squeeze energy out of the approximately 80,000 U. S. dams that currently do not produce power.

As of 2015, pumped storage hydropower has provided 97% of the total utility-scale electricity storage in the United States. Pumped storage hydropower has proven to be a reliable and commercially available, large scale, storage resource.

The majority of pumped storage hydropower facilities have been developed by utilities, both public and investor-owned. Independent Power Producers have shown an increased interest in new pumped storage projects and have filed a number of applications for preliminary permits with FERC. Approximately 80% of the active permits for pumped storage hydropower projects are held by IPPs.
These preliminary permits represent more than 15,000 MW of capacity.

Estimated 62% Growth – Pumped Storage Hydropower by 2050 (51GW)

Some of the challenges developers face for new pumped storage hydropower projects have to do with environmental issues. Previously, most operating storage projects required the construction of at least one dam along main stream rivers altering the ecology of the river system and affecting the fish and other wildlife. A relatively new approach is to locate the reservoirs in areas that are physically separate from existing river systems. These projects are termed “closed –looped” pumped storage and have minimal to no impact to the existing river system. Once the reservoirs are filled, the additional water requirement is minimal operational make-up water to offset evaporation and seepage losses.

Another signification challenge is the long timeline for development of a new project. Under the current FERC licensing process, obtaining a new project license to construct takes 3 to 5 years or longer before the developer can begin construction. Currently the licensing process is the same for both open- looped and closed- looped projects. At this time there is not an alternative licensing process for low-impact or close-looped projects to shorten the time frame. In addition to the licensing process, a large scale project will take at a minimum 3 to 5 years or longer to construct depending on the environmental requirements.

How are you doing Mr. Claus? We hope this letter finds you well and in good spirits. Just like you, this time of year is extremely busy for us (maybe not as busy as you can get, but pretty hectic as you can imagine), but we thought was a good idea we write you. We understand you typically get these types of letters from boys and girls from all over the world, but why not one from us. You’re a jolly good elf, and we hope you may find some time in the busy holiday to add us to your Christmas Eve delivery list.

First, let me tell you we’ve been good this year. Our year-to-date production of natural gas is down only 0.2 Bcf/day from last year’s record production level of 72.4 Bcf/day, which has been impressive in the lower price environment that permeated 2016. We achieved a new record in storage this year, posting a 4.047 TCF number as we neared the end of November. Finally, we began to see our first real significant exports of LNG out of the Sabine Pass terminal, with increased volume to come in 2017. Overall a good year, but not without its challenges.

Based on our performance this year and in the past, we hope you would agree that we deserve some gifts, and we wanted to give you a quick list of what we are hoping to find in our stockings for the coming year.

COLD COLD WINTER

As you know in the North Pole Santa, the colder the weather, the more wood for the fire to heat the elves’ homes. The same goes for us, the colder the weather and the longer the duration of the cold, the more demand for gas and the more pressure on prices. As an industry we’ve suffered through two straight generally mild winters, which have led to weak pricing heading into the new gas year. It would be very helpful to get a cold winter this year, specifically targeted over the Midwest and Northeast, and for it to hang around all the way through March. The impact on pricing from such an event would help us bring on more supply in these areas, and maybe incentivize us to increase exploration and increase the gas rig count from its record lows of 2016. While end-users may be unhappy with the increase in prices, we believe the addition of new supply would eliminate the potential for a major price shock in the market if a major demand event where to occur and more production is good in the long-term.

MORE PIPES FOR THE MARCELLUS

With the growth of shale gas out of the Marcellus play in PA and OH, we have had difficulty getting this abundant volume to markets that need it. Pricing in the region has been deflated (we saw Dominion at sub-$1.00/Dth this year), and gas has had nowhere to go. There are several projects underway in the region including Rockies Express, Columbia Gas Transmission, and Tennessee Gas Pipeline to name a few, but they have either been slow to complete or not alleviated the surplus. More pipeline capacity flowing out of the Marcellus would be a welcome gift this year, especially to serve the Northeast (Constitution Pipeline completion), the Gulf of Mexico, and Mexico exports. If you wanted to throw in a shiny new LNG export terminal in the region that would be great as well, although wrapping it may be a chore.

A NEW CLEAN POWER PLAN

We do know that Santa is apolitical, and think that’s a good strategy for a sovereign state operated out of unclaimed territory in the North Pole, however, we wouldn’t mind if you could deliver us a political solution under the tree this year. A delay in implementation or complete overhaul of the Clean Power Plan would definitely be a boom to our industry over the next few years. The battle with coal is over, and we have won, replacing it as the feedstock of choice for almost all new generation entering the U.S. electrical grid. The Clean Power Plan would muddy the waters for us, forcing natural gas to cede generation share to renewables including wind and solar. With the Clean Power Plan removed, natural gas would continue its dominance as the fuel of choice for the country’s growing power needs.

THE NEXT BIG SHALE PLAY

As with any fossil fuel, the question always begs “Where next?” The Marcellus and Utica plays have changed the face of our industry, but they can’t pump out gas forever. Shale wells deplete at a much faster rate than traditional wells and with the increase demand for natural gas through the country and the world we believe a new shale formation would be beneficial to push gas into the next decade and beyond. Wolfcamp in Texas may be that play, with current estimates showing it to the be the largest oil/gas producing shale play in the U.S. However, the majority of the product in the region appears to be oil, which could limit activity in the region depending on the complex movements of the global oil market. We don’t want to be selfish, but a “gas-only” shale play would be nice, and would mean we wouldn’t have to share or work with some of the big bullies on the oil side of the fence.

So that’s our list for Christmas this year Mr. Claus. We appreciate your time and consideration and do hope you can find it in your heart to make our Christmas wishes a reality for 2017 and beyond.

This year’s two mainstream presidential candidates are divided on nearly every issue, energy being one of them. In one case, there could be significant changes to the focus of the nation’s energy policies and research. And in the other case, the U.S. could see many current policies continued and expanded and little change to the administration’s core principals related to energy. There are five categories that energy related commentary from Hillary Clinton and Donald Trump tend to encompass.

Coal

It’s been said that Trump will have a pro-coal policy. He has committed to reviewing all anti-coal regulations and has vowed to remove the moratorium on new coal leases on federal land. Meanwhile, Clinton is determined to regulate fossil fuels by phasing out their subsidies and eventually eliminate their use altogether. Trump claims that Clinton’s policies will put coal miners out of work but she has addressed this with a plant to invest $300 million in job creation in communities who current depend heavily on the coal industry.

Natural Gas

Clinton has referred to natural gas as a bridge fuel, implying we should only be relying on it temporarily for the bulk of our energy needs while we develop and expand renewable energy options. She has not indicated, however, the length of the bridge. Her policies could limit natural gas production as she has shown opposition to hydraulic fracturing and building new pipelines. Trump has promised growth to the natural gas industry just as he has to coal. However, considering they are each other’s closest competitors, it’s hard to see how both could strengthen simultaneously.

Renewable Energy

Renewable energy is not a focus of Trump’s campaign one way or the other, but he has been critical of wind power’s impact on wildlife. This topic comes up a lot with Clinton, though. She wants to invest significantly in renewable energy development including installation of 500 million solar panels in the U.S. in her first term and increase tax credits for renewable energy sources.

Global Warming

Clinton’s position on climate change tracks closely with that of President Obama. She supports the Clean Power Plan and wants the U.S. to continue to act as a leader in fighting climate change. Although he denied it in the second presidential debate, Trump was credited with saying that global warming is a conspiracy put forth by China. Today, he acknowledges its existence but does not agree with the position that it is man-made. He wants to roll back regulations meant to protect the environment and end both the Clean Power Plan and the Climate Action Plan.

International Perspective

Trump is firm on his stance for United States energy independence, but has not given details on what would become of the international energy trading that already takes place today. On the other hand, Clinton hopes to modernize the nation’s electric grid and in the third presidential debate said she wants that grid to cross international borders. She emphasized the importance of trading energy with neighbors of the U.S. but at the same time does not want the country dependent upon the Middle East to meet energy needs.

The winter of 2013-14 was one of the worst on record for the United States. Last winter, 2015-16 was characterized as the winter that wasn’t. When extreme cold weather does show up, the natural gas industry gets hit the hardest. Prices can rise due to the high level of demand that comes along with below zero temperatures and diminishing supply.

With extremely cold temperatures, the interstate pipelines work hard to keep the gas flowing at maximum capacity in order to meet the high energy demands of its pipeline’s customers. Almost nothing in the pipeline can fail without causing some fluctuation in price or supply at one or more points in the delivery chain.

In 2014, TransCanada Pipeline (TCPL) experienced a fire on the Emerson lateral on Jan. 25 which caused prices for natural gas to skyrocket in the upper Midwest. Many natural gas customers were curtailed, facing a reduction of gas deliveries for hours and even days due to a shortage of supply as demand for service exceeded capacity.

Some plants and facilities were prepared with emergency plans in place and access to alternative fuels; others were not. As a commercial or industrial natural gas customer, it is important to know how to prepare for curtailment and the necessary plans to engage during curtailment. The following are some important points on how industrial/commercial facilities can do just that, rather than be caught off guard when curtailment occurs:

Expect Curtailment

There are two major reasons for curtailment. The first is what several major natural gas pipelines experienced in January, when the cold was so widespread from coast to coast and border to border that pipelines were unable to deliver adequate supplies. On these extended cold days, the pipeline does not have a chance to recover. The natural gas stored during the warmer months is often very low late in the winter due to heavy withdrawals and the lack of opportunities for replenishing storage volumes.

The other type of winter curtailment is caused by a rupture which can be an extremely severe issue. When a rupture occurs, pipelines are unable to meet load demand, so loads are cut drastically. Prices tend to follow supply and demand rules: As demand gets tight, prices rise.

Ruptures can result in serious price increases, which is exactly what happened in the Midwest last January. The explosion in Canada affected deliveries to the middle of the heartland, which resulted in gas prices soaring into the $40-80/Dth range, plus penalties of as much as $113/Dth for taking more gas than originally nominated. This price spike represented an extremely expensive departure from the normal price range of $3-$5/Dth.

Weighing Cost-Benefit of back-up fuel

Municipalities and some industrial/commercial facilities need an alternate fuel source such as propane or Liquefied Natural Gas (LNG). The costs of a standby fuel system can pay for itself in the long run if health and safety are involved of your plant’s production line cannot be interrupted without significant expense. While backup options, such as propane air systems and backup generators can be expensive to purchase and maintain and may be rarely used, their value in an energy crisis is unquestionable.

Any backup system needs to be tested on a regular basis to ensure that it will be ready for operation at any moment. This means ensuring that plant and backup facility operators have tested all the elements of the backup system without using natural gas. To avoid critical production issues, testing of backup fuel sources should happen at the beginning of each winter to ensure they are ready to perform.

Staying On Top Of Weather

A natural gas pipeline distribution system is built to serve the coldest hour of the coldest day of the year for all of its firm service customers. It’s difficult to predict when this extreme cold will hit, the level of severity or how long the cold snap will last. Having access to accurate and clear weather forecasts, including how long a cold snap is predicted to last and the severity of the weather event, will allow a company to make informed decisions before a curtailment hits.

Know Pricing

Curtailment can be expensive. If a company chooses to continue operations during curtailment, fines can be extremely high. Make sure to weigh the costs of stopping or cutting back operations against continuing operations with a penalty. This means calling the pipeline, utility or an energy management services provider to fully understand if continuing to run production is even a possibility, and if so, what the cost will be. Figuring out how much it will cost to shut down operations completely or rely on an alternative fuel source during curtailment will allow a company to make informed decisions based on cost-benefit analysis.

Even if it’s never happened before, it’s important to remember that curtailment can happen – whether for a couple of hours or for days at a time – and companies should have a plan in place before it does. No facility is immune to events such as the TransCanada pipeline rupture.

According to the Office of Electricity Delivery and Energy Reliability of the U.S Department of Energy, ten unique energy events (7 are natural gas related) were identified as Major Events in 2015, compared with 12 events in 2014. The figure below maps these events:

One Step Ahead

As we continue to experience extremely severe and volatile winter weather in the United States, it will become more important for all commercial/industrial end users to know what to do when faced with curtailment how much the financial implications will be associated with that curtailment. A company should always have the appropriate knowledge to consider what options make the most sense.

Around our homes and around the office, much of what we do revolves around food. We all need food for survival. It is pretty straight forward. When we are hungry, we want to eat, we want to know what time we are going to eat and we always like food to be available. Large volume natural gas customer needs are also pretty straight forward. They want their natural gas on time, at a specified point, and available to meet their demand.

While the options available to us when it comes to dietary choices seem endless, the options of how we purchase natural gas are not quite as lengthy. There are however, options available and choices that need to be made. Most options can be categorized into two groups: Customers who own capacity on a pipeline and customers who purchase delivered supply from a natural gas marketer.

When a customer owns their own natural gas pipeline capacity, they are committing to an “a la carte” way of buying natural gas. Just like going to an up-scale restaurant, you are purchasing each piece of your meal separately to complete the experience. Buying natural gas supply from a marketer is more like buying a combo meal from any of the local fast-food restaurants. Most everything is provided for you in an all-inclusive price and in a nice little pre-decided package. The results of each are the same; you are now less hungry and you have received natural gas at your facility. Everything else just depends on what your needs are at a given point of time.

We can all relate to why we may choose a nice steakhouse over a combo meal, so let’s leave the food analogy behind for just a moment. Let’s consider the reasons you may choose between owning capacity and buying from a marketer. Owning capacity on a pipeline means you are committed to a receipt and delivery point at a specified price for the length of the agreed upon term. The terms of the agreement are very specific on how the natural gas flows and can be 10 to 15 year contracts.

Customers may elect to own capacity for any of the following reasons:

They have constructed their own pipeline attached to a major inter/intrastate pipeline;

Their business plan and subsequent production schedule certainty extends far into the future;

Their facility is located in a constrained area;

Or their operation cannot be interrupted for any reason.

Owning capacity gives a great deal of control to the customer. Along with this control comes the responsibility of managing the capacity or contracting with a third party to manage it for you. When buying from a marketer, you agree to a price, delivery point and level of management you require for the natural gas. Because a marketer potentially owns multiple pieces of capacity, there is flexibility within the terms of the agreement as to how the natural gas may flow to the delivery point. Marketers may also have specialized products they have developed that offer benefits to customers based on a geographic, utility or pipeline dynamic.

Capacity and marketer choices available in the region around your facility can be overwhelming. Sorting through the options and offering solutions is where U.S. Energy can help. We are here to assist your teams through the entire procurement process. We can help you identify options in the natural gas world that you are not aware of. Give U.S. Energy a call and allow us to assist your team.

For many years the number of active drilling rigs has been used as a general indicator of future gas production. This premise was never perfect and developments over the past few years have continued to break down this indicator relationship.

Chart 1 below shows oil and gas drilling activity since 2008. From 2009 through 2014 oil prices were generally increasing and natural gas prices were declining. Oil and gas drillers reacted to this pricing environment by shifting drilling resources from gas to oil. However during this time of decreased drilling of gas wells, gas production increased substantially as shown in Chart 2. Clearly the decreased gas drilling count did not lead to lower gas production during this period.

Chart1.

Chart 2.

The drilling rig count is an enumeration of how many rigs are drilling wells, not how many wells are producing gas or oil. Also the number of rigs actively drilling doesn’t necessarily indicate how much gas the new wells being drilled will produce. Further, a well that has been drilled isn’t ready to produce gas until it has been completed and connected to a gas pipeline. Delays can occur between drilling and connection. There can be several reasons for delays. For instance, gas prices may have dropped too low to justify completing and connecting the well. Another reason can be that a pipeline connection is not immediately available or there is not sufficient capacity in the connecting pipeline to transport gas to market. Also, crews may not be available to finish the well completion work.

The past ten years have seen remarkable advancements in drilling oil and gas wells. This has further strained the relationship between the count of active drilling rigs and gas production.

Drillers are better at knowing where to drill for oil and gas than in the past. Technological advancements provide better indications of what is below the earth’s surface. This increases the success rate of drilling wells which in turn reduces the number of rigs needed to drill wells that successfully produce gas and oil.

Advancements in fracking and horizontal drilling methods have allowed drillers to successfully produce gas from less permeable rock formations (shale) than ever before. Better fracking techniques rupture rock formations and create better paths for gas and oil to reach the well. Improved horizontal drilling allows drillers to bore a well better following the oil and gas producing zone rather than previous techniques that only punctured zones perpendicularly. This exposes the well to more productive areas of the oil and gas reservoir and increases gas flow. Fewer rigs are needed to drill wells into productive areas than before.

Many of these shale formations containing oil and gas are relatively shallow. Wells drilled into these producing areas can be drilled quicker because drillers don’t have to penetrate as far into the earth as the wells being drilled prior to the availability of fracking and horizontal techniques. This decreases the drilling time and costs which decreases the number of rigs needed to drill wells.

Multiple wells can be drilled from the same location using directional and horizontal drilling. This means drilling rigs don’t have to be shut down, relocated and set back up before drilling a new well. A single rig can drill more wells faster.

Another important change over the last decade is that it is no longer as easy to designate a well as an oil or gas well. Many more wells are producing both oil and gas. Therefore looking at a count of the rigs drilling for gas can underestimate the future number of wells that will be producing gas.

In conclusion, the number of rigs drilling for gas is related to future gas production, but cannot be used as a primary indicator without consideration being given to other important factors.